About one-half of oil recovery worldwide is produced by waterflooding. Significant quantities of oil, typically, more than one-half of the original oil in place, remain in the reservoir after waterflooding and are commonly the target for improved oil recovery processes. When crude oil is displaced from rock by water, as is common practice in the process of oil recovery by water flooding, laboratory tests show that changes in the crude oil/brine/rock properties occur. For example, laboratory coreflood studies have shown increased oil recovery is achieved by waterflooding using low salinity water, compared with injection of seawater or high-salinity produced water (See, e.g., “Salinity, Temperature, Oil Composition And Oil Recovery By Waterflooding” by G. Q. Tang and N. R. Morrow, SPE Reservoir Engineering 12(4), 269-276 (November 1997); “Influence Of Brine Composition And Fines Migration On Crude Oil/Brine/Rock Interactions And Oil Recovery” by G. Q. Tang and N. R. Morrow, J. Pet. Sci. Eng. 24, 99-111 (1999); and “The Role Of Reservoir Condition Corefloods” by K. J. Webb et al., 13th European Symposium On Improved Oil Recovery, Budapest, Hungary (April 2005)). The improved oil recovery results from complex crude oil/brine/rock interactions. Laboratory corefloods suggest that as much as 50% additional oil could be produced if low-salinity water (<4000 ppm) is injected into the reservoir, as opposed to seawater or higher-salinity production water. These results have been shown to be applicable to the near well bore environment of an oil field in “Low Salinity Oil Recovery-Log-Inject-Log” by K. J. Webb et al. SPE 89379, 2004 SPE/DOE Fourteenth Symposium on Improved Oil Recovery, Tulsa, Okla., U.S.A. 17-21 (April 2004). A producing well (that is, a well that produces oil) was selected for the test to ensure that all saturation changes occurred under controlled test conditions and that the results would not be affected by previous high rate water injection. 10-15 ‘pore volumes’ of high-salinity brine were injected into the ‘volume of interest’ to obtain a baseline residual oil saturation. This was followed by sequences of more dilute brine followed by high-salinity brine for calibration purposes. At least three further passes were run to ensure that a stable saturation value had been established after injection of each brine. Extensive water sampling was conducted to confirm brine salinities and increase confidence in the quantitative saturation results. The results were consistent with previous laboratory tests from other fields, and showed 25-50% reduction in residual oil saturation when waterflooding was undertaken using low-salinity brine.
The injection of discrete volumes of fluid in a reservoir recovery process application is known. For example, in the Water Alternating Gas (WAG) process, one tenth of the reservoir hydrocarbon volume might be injected over a period of one year with change from carbon dioxide injection for one month to water injection for one month, and so forth.
Significant quantities of oil still remain in the reservoirs after primary and secondary recovery.